Message-ID: <25023319.1075844063523.JavaMail.evans@thyme> Date: Thu, 27 Jul 2000 06:16:00 -0700 (PDT) From: lorna.brennan@enron.com To: bill.cordes@enron.com, john.goodpasture@enron.com, michael.ratner@enron.com, steven.harris@enron.com, jeffery.fawcett@enron.com, lorraine.lindberg@enron.com, kevin.hyatt@enron.com, christine.stokes@enron.com, tk.lohman@enron.com, michelle.lokay@enron.com, lindy.donoho@enron.com, lee.huber@enron.com, susan.scott@enron.com, sarabeth.smith@enron.com, steven.january@enron.com, julia.white@enron.com, vernon.mercaldo@enron.com Subject: The West: Keeping Its Fingers Crossed - CERA Alert Mime-Version: 1.0 Content-Type: text/plain; charset=us-ascii Content-Transfer-Encoding: 7bit X-From: Lorna Brennan X-To: Bill Cordes, John Goodpasture, Michael Ratner, Steven Harris, Jeffery Fawcett, Lorraine Lindberg, Kevin Hyatt, Christine Stokes, TK Lohman, Michelle Lokay, Lindy Donoho, Lee Huber, Susan Scott, Sarabeth Smith, Steven January, Julia White, Vernon Mercaldo X-cc: X-bcc: X-Folder: \Michelle_Lokay_Dec2000_June2001_1\Notes Folders\Discussion threads X-Origin: LOKAY-M X-FileName: mlokay.nsf ---------------------- Forwarded by Lorna Brennan/ET&S/Enron on 07/27/2000 01:07 PM --------------------------- webmaster@cera.com on 07/26/2000 10:57:49 PM To: Lorna.Brennan@enron.com cc: Subject: The West: Keeping Its Fingers Crossed - CERA Alert ********************************************************************** CERA Alert: Sent Wed, July 26, 2000 ********************************************************************** Title: The West: Keeping Its Fingers Crossed Author: Zenker, Moritzburke, Snyder E-Mail Category: Alert Product Line: Western Energy , URL: http://www.cera.com/cfm/track/eprofile.cfm?u=5526&m=1286 , A strong dose of summer weather in June propelled West-wide demand levels up by nearly 12 percent over the same period in 1999. These higher demand levels provided the year's first example of the power price spikes that can be produced when the West's tight capacity intersects with normal summer load levels, lower-than-normal hydroelectric levels, strong gas prices, and California's immature wholesale power market structure. As power markets reacted in June with unprecedented price strength throughout the region, regulators and the California Independent System Operator (ISO) intervened to dampen markets from a maximum of $750 per megawatt-hour (MWh) to $500 per MWh.* Although some market participants have filed protests at the Federal Energy Regulatory Commission to raise or eliminate the caps, utilities, legislators, and consumer advocates are moving to protect consumers or completely redesign what they perceive as a flawed market. As western markets move through the critical July-August peak electricity demand period, market participants and regulators alike are wondering if power supplies will be sufficient and if price levels will rival those in June. CERA expects that western supplies will be adequate under normal summer weather conditions, barring abnormal unit and transmission line outages. However, normal August weather conditions will push demand levels significantly higher than in June, creating an even tighter supply-demand balance, straining the ability of the transmission system to supply key demand regions adequately. A hot weather event could exhaust both in-state and imported supplies for California. The tight supply and demand situation will almost certainly prompt a strong price response, similar to that in June. This will fuel the unease of regulators in states that have restructured their markets and in those that are considering restructuring. Even as regulators' continued support of restructured power markets begins to waver, a weather event that forces regional blackouts would force regulators to intervene. CERA's outlook for August power markets is driven by * High peak loads. Under normal weather conditions, West-wide August loads will be on average 1,400 megawatts (MW) higher than last August. The peak load in California is expected to push capacity margins to 6 percent, even after curtailing interruptible load. * Lower hydroelectric output. As the West enters its peak load period, hydroelectric production is expected to decline systemwide by roughly 3,900 average megawatts (aMW) from July to August. Compared with the high, sustained output of last August, hydroelectric output this August, although roughly average on a historical basis, will be roughly 4,900 aMW (20 percent) lower. * High levels of gas-fired generation. Compared with August 1999, higher utilization rates, along with gas prices that have climbed $1.88 per million British thermal units (MMBtu), will increase the incremental cost of energy production by over $20 per MWh. Although CERA expects power prices in August to diverge from production costs owing to the expected supply tightness, higher production costs will create a higher floor for energy prices in all periods of the day. The extremely tight power supply-demand balance within the West, and within California specifically, has resulted in unprecedented high summer gas demand for power generation. This high demand level-combined with seasonal storage injection needs in California-has pushed up utilization rates on pipelines into California and pushed Topock differentials over $0.75 per MMBtu to the Henry Hub. Strong demand should continue through August in the West and support premium pricing at Topock. The Rocky Mountains represent the opposite extreme to the high premium placed on Topock deliveries. In the Rockies supply is building relative to export pipeline capacity, and market access is becoming a challenge. Weak seasonal demand compounds the problem; the strong western demand for gas for power generation does not extend to the Rockies. Generation within the region remains nearly all coal-fired. These regional pressures should remain a feature of western gas markets through September. Moderate summer weather and reassuring injection rates nationwide during recent weeks have allowed some easing in prices at the Henry Hub. However, summer is not yet over and absolute storage inventories are still at critical levels. Higher gas prices are likely to resurface. Regional Power Market Drivers August demand under normal weather is expected to rise by an additional 7 percent, or nearly 5,500 aMW, over average June levels (see Table 1). Peak demand levels should exceed those in June as well, with a coincident peak over the whole Western Systems Coordinating Council (WSCC) of 118,600 MW expected under normal weather conditions in 2000, a 2.7 percent increase over the weather-muted 1999 peak. California alone should experience peak loads that are approximately 3,600 MW higher than peak levels in June. Available generation capacity in the West has been at normal levels for this time of year, although coal-fired plants are responding to a record production year with repeated but short-lived outages. The steady decline in hydroelectric generation will remove 3,900 aMW from the West resource base when compared with July levels and about 6,800 aMW since June, although reservoir refilling operations temporarily removed significant quantities of hydroelectric generation during portions of June. Given hydro operators' economic interest in maximizing on-peak production at the expense of off-peak production, the loss of capacity during the on-peak period will be lower than these levels. August will be a critical month for the heavily import-dependent state of California. While the state will be drawing approximately 7,000 aMW of imports during August to meet demands during peak periods, CERA expects the level of imports to exceed 8,200 MW during peak demand conditions. The Southwest's need to supply native demand first will limit its ability to export to California, and lower year-over-year hydroelectric production in the Pacific Northwest will limit exports from that region. Pacific Northwest CERA expects Pacific Northwest demand in August to climb by nearly 1,300 aMW when compared with June levels. The water supply for the Pacific Northwest has declined to 91 percent of normal levels for the Lower Columbia owing to warmer-than-normal weather in June. In addition, normal seasonal decline in runoff levels will drop about 6,000 aMW from the resource base when compared with levels in June (see Table 2). Generation plant operators have responded to both growing native demand and a robust export market by running coal and gas-fired generation at high levels. Although less than 4,000 MW of gas-fired generation is currently available in the region, it has been running at high utilization rates. High energy demand in California for Pacific Northwest energy will keep differentials low between the regions. As in June, Pacific Northwest prices will respond in kind to the volatility CERA expects to occur in California in August. In addition, if hot weather in the Pacific Northwest pressures regional energy reserves, local prices will rise to keep energy in the region, potentially causing prices in the Pacific Northwest to move higher than those to the south. California California is entering the peak load season with relatively little generating capacity down for maintenance. Although hydroelectric output continues to decline, statewide reservoir storage levels remain high at roughly 118 percent of normal. Nevertheless, declining hydroelectric production is expected to remove about 730 aMW when compared with hydroelectric production levels in June. Normal summer weather will push demand in the state up by about 3,600 aMW over June levels, which were high (see Table 3). California's peak load is expected to exceed 57,000 MW, compared with a peak load in June of approximately 53,500 MW (43,447 MW on the state's ISO system alone, according to its own estimate). Assuming normal plant outage rates, this demand level will necessitate the import of about 8,200 MW of energy to meet the statewide peak. Even after curtailing the approximately 2,800 MW of interruptible load available for tight supply situations, the state has a precarious 6 percent capacity margin during the system peak. An extreme hot weather event could push state loads up by an additional 3,000 MW. Outages are likely if additional imports are not available. A capacity limit of 4,600 MW will be in place during the summer for energy exports from the Pacific Northwest to Northern California. The import limit from the Pacific Northwest to southern California will be 3,100 MW. Rockies and Southwest August demand levels in the combined Rockies/Southwest region will increase only slightly above levels in August 1999, climbing approximately 275 aMW, as loads in the region-unlike the rest of the below-average WSCC-were near normal last August. Even so, August loads will increase demand by over 1,250 aMW when compared with levels in June of this year. As with last year and this June, supplies in the region should be sufficient to meet peak demand conditions under normal weather, although growing loads in the Rockies/Southwest region have reduced its ability to supply neighboring regions with energy during peak demand conditions. High loads driven by hot weather will keep the region's prices high. Differentials between the region and California will be tight, but California, having tighter supply-demand balances, will need to price at a premium to attract energy. The high-capacity transmission ties between the Rockies/Southwest and the California market, which is about 150 percent the size of the Rockies/Southwest market, will ensure that prices in the Rockies/Southwest stay close behind California prices whenever loads are high in California. Regional Gas Market Drivers Evidence of pipeline bottlenecks has emerged across the West, and supply and demand forces over the next year look likely to intensify these pressures. Since the Northern Border expansion in late 1998, narrow north-south and east-west differentials across pricing points defined the market. This summer, the continuing supply growth in the Rocky Mountains has widened differentials between the Rockies and the rest of the West. At Topock, increasing gas demand in California and high utilization rates have resulted in high premiums. Overall in North American gas markets, strong storage injection rates in recent weeks have allowed some easing in prices-from an early July Henry Hub price of $4.50 per MMBtu to under $4.00 per MMBtu. However, despite these high injection rates, the supply-demand balance and absolute level of storage inventories remain precarious. Summer is not over and higher nationwide power loads in weeks to come will likely cut into storage injections and boost prices. The ongoing competition between power and storage for supply should support an average Henry Hub price of $4.20 per MMBtu in August. Through the end of the summer, differentials in the West should hold near current levels. The pressure of growing Rocky Mountain supply will continue until heating loads start climbing in the fall. In California high seasonal power loads should continue through August with hot weather and continued declines in hydroelectric generation. Demand strength is expected to continue. Across the West, August demand for gas should climb from 9.8 billion cubic feet (Bcf) per day in June to 10.4 Bcf per day, buoyed by an increase in gas demand for power generation (see Table 4). California High gas demand for power generation within California will continue through August. CERA expects an increase from the state's June demand levels of 5.6 Bcf per day to 6.2 Bcf per day during August. The increase stems from declines in hydroelectric generation and increases in overall power loads. Total demand is expected to exceed last year's demand level by 1.2 Bcf per day. This will increase flows on pipelines into California, reduce the state's storage surplus, and sustain high prices. CERA expects pipeline utilization rates during August to average 95 percent (see Table 5). CERA expects an August Topock-Henry Hub differential of $0.45 per MMBtu (see Table 6). Pacific Northwest Despite the extremely high prices at Topock and high demand in California, until recently gas at Malin priced at a slight discount to Henry Hub prices. After averaging $0.17 per MMBtu below the Henry Hub during the third quarter last year, the differential so far during the third quarter this year is $0.15 per MMBtu below the Hub. This week Malin is pricing at a $0.25 per MMBtu premium relative to the Henry Hub. The Topock-Malin differential has swelled to over $0.60 per MMBtu, signaling intra-California pipeline capacity constraints. Two factors pressured Malin differentials during the early summer. * Pressure on Rocky Mountain and AECO differentials. Prices in the two areas supplying the Pacific Northwest are under some pressure. Increasing supplies in the Rockies are beginning to reach the limits of export capacity and put downward pressure on Rockies prices by limiting external market access. At AECO, although export capacity out of the province is available, almost all of that excess capacity accesses eastern Canada on TransCanada Pipeline. Pipelines into the United States are running near capacity. Because of TransCanada's limited ability to discount interruptible transport, the available space is more expensive and therefore the last to be filled. * Low early summer regional demand. Gas demand in the Pacific Northwest is limited during late spring and early summer by declines in heating loads and very strong hydroelectric output. Even in a normal or dry hydroelectric year, seasonal runoff holds down gas demand for power generation in May and June even as gas demand for power generation begins climbing in California. Increasing power loads are already evident. The first factor will likely endure until heating season begins in late fall and regional demand in the Rockies and western Canada begins climbing. However, gas demand for power generation in the Pacific Northwest has increased already this summer and will continue to climb through the end of July and into August as hydroelectric generation wanes. This added demand-200 million cubic feet (MMcf) per day above June demand levels-will provide some support for Malin prices and limited support for Rockies and AECO prices. Malin-Henry Hub differentials are expected to average $0.05 per MMBtu above the Henry Hub price during August. Rocky Mountains Pressure on regional supplies within the Rockies continues as exports out of the region reach new highs. Differentials to the Henry Hub have widened to over $0.70 per MMBtu and although prices in the rest of the West will gain some support from high power loads, regional demand in the Rockies is expected to remain near low seasonal levels through August. August demand is expected to average 1.2 Bcf per day in the region, approximately equal to June's 1.1 Bcf per day total demand. Demand begins to build during September, but until the heating season begins in October, Rocky Mountain prices will lag well below prices in the rest of the West. CERA expects a Rocky Mountain-Henry Hub differential of $0.60 per MMBtu during August. Although some narrowing in Rocky Mountain differentials looks likely as seasonal demand increases through the fall, the rapid build in supply in the region will likely keep differentials wide during 2001. CERA expects a supply build this year of nearly 300 MMcf per day, followed by a build of over 350 MMcf per day during 2001. Currently, approximately 300 MMcf per day of excess pipeline export exists out of the region, with the largest increment on Transcolorado into the San Juan Basin. Next summer, all capacity will likely run close to full. Until export pipelines expand-the first likely expansion is Trailblazer-differentials will remain wide. For 2001, CERA expects an average annual differential below the Henry Hub of $0.65 per MMBtu. Southwest Differentials in the San Juan and Permian Basins have gained considerable strength relative to Henry Hub prices amid the recent hot weather in Texas. Permian supplies are pricing at a slight premium to the Henry Hub price, and in the San Juan Basin prices have narrowed from an early July differential of $0.35 per MMBtu to a differential of less than $0.20 per MMBtu. CERA expects demand in the Southwest during August of 1.4 Bcf per day, an increase from June's level of 1.3 Bcf per day, but the larger Texas market will determine the relative strength of differentials in those two basins. CERA expects a San Juan differential of $0.30 per MMBtu during August, with a Permian Basin differential of $0.06 per MMBtu. Differentials between the Rocky Mountains and the San Juan Basin have widened substantially over the past two months with supply increases in the Rocky Mountains. Flows on Transcolorado increased from a monthly average of under 20 MMcf per day to over 100 MMcf per day during June. Supply in the two regions is following opposite paths; Rockies supply is climbing rapidly, and San Juan supply has likely peaked and should decline slowly beginning this year. CERA expects a decline in supply of 30 MMcf per day during 2000 relative to 1999 and an additional decline of 150 MMcf per day during 2001. Because of these different outlooks, wider Rockies-San Juan differentials will persist. **end** Follow URL for PDF version of this Monthly Briefing with associated tables. Note: Should the above URL not work, please use the following: http://www.cera.com/client/ce/alt/072600_16/ce_alt_072600_16_ab.html ********************************************************************** Account Changes To edit your personal account information, including your e-mail address, etc. go to: http://eprofile.cera.com/cfm/edit/account.cfm This electronic message and attachments, if any, contain information from Cambridge Energy Research Associates, Inc. (CERA) which is confidential and may be privileged. Unauthorized disclosure, copying, distribution or use of the contents of this message or any attachments, in whole or in part, is strictly prohibited. Terms of Use: http://www.cera.com/tos.html Questions/Comments: webmaster@cera.com Copyright 2000. Cambridge Energy Research Associates